All purpose pumpdown instrument

ABSTRACT

An apparatus for flowing a tool string along a wellbore tubular may include a flow restrictor having a diametrically expanded position and a diametrically retracted position. The flow restrictor may include at least one sealing element that sealingly engages the wellbore tubular when in the diametrically expanded position. The apparatus also includes an actuator configured to move the at least one sealing element to at least a position intermediate of the open and the closed position. The actuator may be responsive to a control signal that is generated locally or transmitted from a remote location.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of U.S. patent application Ser. No. 13/712,534 filed on Dec. 12, 2012 and claims the benefit of priority from the aforementioned application.

BACKGROUND OF THE DISCLOSURE

1. Field of the Disclosure

This disclosure relates generally to method and devices for conveying tools along a wellbore.

2. Background of the Art

During the drilling, completion, workover, and remediation of a hydrocarbon-producing wellbore, it may be necessary to convey a tool string to one or more target depths along that wellbore. One conventional method for conveying a tool string along a wellbore is a “pump down” operation. A “pump down” operation typically involves pumping a liquid (e.g., water) to propel a tool string along a wellbore tubular in the wellbore. The tool string may include “swab cups” or other fixed annular rings or fins that resist fluid flow. For wellbores that have extended non-vertical sections, a significant amount of fluid must flow past the swab cups at a high flow rate in order to provide this propulsive force.

In some aspects, the present disclosure addresses the need for devices and methods that can reduce the amount of fluid needed for pump down operations.

SUMMARY OF THE DISCLOSURE

In aspects, the present disclosure provides an apparatus for flowing a tool string along a wellbore tubular. The apparatus may include a flow restrictor having a diametrically expanded position and a diametrically retracted position. The flow restrictor may include at least one sealing element that sealingly engages the wellbore tubular when in the diametrically expanded position. The apparatus also includes an actuator configured to move the at least one sealing element to at least a position intermediate of the open and the closed position. The actuator may be responsive to a control signal.

In aspects, the present disclosure also provides a method for flowing a tool string along a wellbore tubular. The method may include disposing a flow tool having a flow restrictor into the wellbore tubular, wherein the flow restrictor has a diametrically expanded position and a diametrically retracted position; using a control signal to move the flow restrictor to at least a position intermediate between the diametrically expanded position and the diametrically retracted position; pumping fluid into the wellbore tubular; propelling the flow restrictor and the tool string through the wellbore by sealingly engaging a surface of the wellbore tubular with the flow restrictor in the diametrically expanded position; terminating the pumping once a target depth has been reached by the tool string; and using a control signal to move the flow restrictor to the diametrically retracted position.

Examples of certain features of the disclosure have been summarized rather broadly in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated. There are, of course, additional features of the disclosure that will be described hereinafter and which will form the subject of the claims appended hereto.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, wherein:

FIG. 1 illustrates a well that may use flow tools in accordance with the present disclosure;

FIG. 2 schematically illustrates a flow tool made in accordance with one embodiment of the present disclosure;

FIG. 3 schematically illustrates an embodiment of a flow tool made in accordance with one embodiment of the present disclosure that uses sealing elements as a flow restrictor;

FIG. 4 schematically illustrates an embodiment of a flow tool made in accordance with one embodiment of the present disclosure that uses a sail as a flow restrictor;

FIGS. 5 and 6 schematically illustrate an embodiment of a flow tool made in accordance with one embodiment of the present disclosure that uses a flexible shell as a flow restrictor;

FIGS. 7 and 8 schematically illustrate an embodiment of a flow tool made in accordance with one embodiment of the present disclosure that uses bellows as a flow restrictor;

FIG. 9 schematically illustrates an embodiment of a slip joint for use with bellows;

FIG. 10 schematically illustrates an embodiment of a slip joint for use with an umbrella-type of flow restrictor;

FIG. 11 schematically illustrates an embodiment of a flow tool made in accordance with one embodiment of the present disclosure that uses sealing elements actuated by an actuator;

FIGS. 12-14 schematically illustrate various stages of operation of the FIG. 11 actuator;

FIGS. 15A-C schematically illustrate various stages of deployment of the FIG. 11 flow tool; and

FIG. 16 schematically illustrates another embodiment of a flow tool made in accordance with one embodiment of the present disclosure that is autonomous and sealing elements that can accommodate eccentric tool positions.

DETAILED DESCRIPTION OF THE DISCLOSURE

In aspects, the present disclosure provides methods and devices that can reduce the amount of fluid used while conveying a tool along a wellbore. FIG. 1 illustrates an exemplary wellbore 10 that has been drilled through the earth 12 and into formations 14, 16 from which it is desired to produce hydrocarbons. The wellbore 10 may be cased by metal casing, as is known in the art. The wellbore 10 may have a vertical leg 17 and a non-vertical leg 19. While leg 19 is shown substantially horizontal, a non-vertical leg may be inclined between a vertical and horizontal. The wellbore 10 has a wellbore tubular 20 that extends downwardly from a wellhead 24 at the surface 26 of the wellbore 10. The wellbore tubular 20 may be formed of known wellbore tubulars such as drill string, jointed pipe, coiled tubing, or production tubing. The wellbore tubular 20 may also be casing or liner. The wellbore tubular 20 defines an internal axial flowbore 28 along its length. An annulus 30 is defined between the production assembly 20 and the wellbore casing.

Also shown in FIG. 1 is a tool string 40 configured to perform one or more selected operations in the wellbore 10. The tool string 40 may include perforating guns, packers, bridge plugs, circulating subs, casing collar locators, formation evaluation tools, casing or pipe evaluation tools, wellbore evaluation tools, frac tools, well treatment equipment, and/or other tools used in the course of completing, recompleting, logging, evaluating, remediating, or working over the wellbore 10. In one embodiment, the tool string 40 may be tethered to a non-rigid conveyance device 42 such as a wireline (power and data), an e-line (power only), or a slickline (no power or data). The non-rigid conveyance 42 may be a flexible cable that has sufficient tensile strength to pull the tool string 40 out of the wellbore 10. A fluid mover 44 may be used to pump pressurized fluid into the wellbore tubular 20. The fluid mover 44 may be a pump for pumping water, drilling mud, or any other suitable liquid carrier into the flow bore 28 of the tubing 20. This fluid may return via the annulus 30 to the surface. The tool string 40 may include one or more flow tools that use adjustable flow restrictors to selectively block fluid flow along the wellbore tubular 20. Specifically, these flow tools can open to propel the tool string 40 into the wellbore 10 and then close while retrieving the tool string 40 out of the wellbore 10. Illustrative embodiments are discussed in connection with FIGS. 2-16 below.

Referring to FIG. 2, there is shown one embodiment of a flow tool 50 in accordance with the present disclosure. The flow tool 50 may be connected to a tool string 52 that is configured to perform one or more desired well operations. The flow tool 50 may include a variable diameter flow restrictor 54 that is actuated by a slip joint 56. Centralizers 59, which may be bow springs, ribs or stands, may be used to center the flow tool 50 in the wellbore tubular 20. The flow restrictor 54 is an annular-shaped member that can diametrically expand and retract to block flow along an annulus 55 between the wellbore tubular 20 and the flow tool 50. In the diametrically expanded condition, the flow restrictor 54 may be approximately the same diameter as an inner diameter of a wellbore tubular 20 and form a sliding seal with the adjacent wellbore wall 21. This form of contact may be referred to a hydraulic sealing engagement or simply ‘sealing engagement,’ but does not require physical contact between adjacent surfaces. Rather, fluid flow is sufficiently restricted to generate pressure differential sufficient to propel the flow tool 50 along the wellbore. A space or gap may separate the flow restrictor 54 partially or completely along a circumference during a sealing engagement. This seal allows the relatively higher pressure uphole of the flow tool 50 to propel the tool string 52 through the wellbore tubular. Moreover, the seal may be compliant in that the flow restrictor 54 may bend or deform as needed to pass through obstructions along the flow bore 20 and expand once the obstruction has been passed. It should be understood that the seal need not be a fluid-tight seal and that some fluid flow may still occur through the seal.

Referring now to FIGS. 2 and 3, there is shown a flow tool 50 that uses flow restrictor 54 formed as sealing elements 62. The sealing elements 62 may be segmented pie-shaped members that are circumferentially arrayed around a body or support 64. The support 64 may be a mandrel, a tube, a rod, or other suitable support member. The sealing elements 62 may be interleaved petals or thin plates that are fixed at one end to the support 64. Thus, the sealing elements 62 rotate about the fixed end when opening. When open, the sealing elements 62 form a basket shape that captures flowing fluids. The sealing elements 62 may be formed of a metal, an elastomeric material (e.g., rubber), and/or a composite material. As seen in FIG. 2, in some embodiments, the flow tool 50 may also include a liner 58 that lines the radially inner surface of the sealing elements 62. The liner 58, which may also be connected to the slip joint 56, catches debris and other material that may otherwise become lodged in the sealing elements 62.

FIG. 4 shows an embodiment of a flow tool 50 that is similar to that shown in FIGS. 2 and 3. However, in the FIG. 4 embodiment, the flow restrictor 54 is formed as a sail 72 (or canopy) that is fixed to the support 64. The sail 72 may include pleats for folding into a compact condition. In embodiments, the sail 72 may include rigid or semi-rigid support members 74 such as rods that assist in the sail 72 having a pre-defined shape (e.g., annular) when opened. The sail 72 may open in an umbrella-type fashion with the concave side facing the downwardly flowing fluid. The sail 72 may be formed of pliant materials such as fabric, cloth, an elastomer, or suitable material.

Referring to FIGS. 2-4, the sealing elements 62 or the sail 72 may be closed using a ring 66 that may be pulled around the sealing elements 62. The ring 66 may be disposed on the outer surface of the support 64 such that the ring 66 can slide axially over the sealing elements 62 or the sail 72. In the first position shown in FIG. 2, the ring 66 may be positioned near the support 64 so that the sealing elements 62 or the sail 72 are free to expand diametrically. In the second position shown in FIG. 4, the ring 66 slides over and compacts the sealing elements 62 or the sail 72.

Referring to FIG. 4, in embodiments, the slip joint 56 may be used to axially slide the ring 66 between the first position at the support 64 and the second position around the sealing elements 62 or the sail 72. The slip joint 56 may be a tubular assembly that can axially lengthen and shorten depending on the amount of applied tension. In some arrangements, the slip joint 54 may be a telescoping type device that has an upper section 78 that is connected to a lower section 80. The upper and lower sections 78, 80 may slide relative to one another. The upper section 78 may be connected to the conveyance device 42 (FIG. 2) and the lower section may be connected to the ring 66 using one or more links 82. The links 82 may pass through slots (not shown) or other suitable openings in the sealing elements 62 or the sail 72. The ring 66 may also be axially displaced by other arrangements such as tethers or cables that go over the sail 72. When the joint 56 is in the axially shortened condition, the ring 66 is near or at the support 64. Axial movement of the upper section 78 away from the lower section 80 pulls the links 72 away from the lower section 80 and slips over the ring 66 and retracts the flow sealing elements 62 or the sail 72.

The slip joint 56 may also be configured to pull the liner 58 out of the sealing elements 62 or the sail 72 before either of these features are closed. For example, the liner 58 may be connected by a suitable linkage or wire to the upper section 78. The connection may be arranged that the liner 58 is moved before the sealing elements 62 or sail 72 are closed.

Depending on the application, additional features may be used to facilitate the opening and closing of the flow restrictor 50. For example, biasing elements such as springs may be used to urge the slip joint 56 to either the open or the closed position. Similarly, biasing elements may be used to urge the flow restrictor 50 to either the diametrically expanded or the diametrically retracted condition. These biasing elements may be used to establish a force value (e.g., tension, pressure, etc.) that must be exceeded for an action to occur or to provide additional force for moving or shifting to a particular position or condition.

An exemplary mode of use will be described in connection with FIGS. 1-4. To begin, the flow tool 50 and the tool string 52 are inserted into the wellbore tubular 20 (FIG. 1). The tool string 52 may be coupled to a conveyance device such as a wireline 24. Initially, the lower section 80 positions the ring 66 such that the sealing elements 62 are free to radiate outward and obstruct the flowing fluid. The flow tool 50 and the tool string 52 may travel primarily under the force of gravity down the vertical section 17 and then enter the horizontal section 19. Because no fluid is being pumped into the wellbore tubular 20 during this initial descent, the sealing elements 62 remain in a generally retracted condition. After entry into the horizontal section 19, or when gravity can no longer move the tool string 52, a fluid, such as water, is pumped into the wellbore tubular 20 using a fluid mover 44 (FIG. 1). The flowing fluid causes the sealing elements 62 to rotate radially outward and contact the adjacent wellbore tubular surface 21. This fluid obstruction generates a pressure differential that propels the tool string 52 along the wellbore tubular 20. When the tool string 52 is positioned at the desired depth along the wellbore, the fluid circulation is stopped and one or more desired well operations may commence. Throughout this process, a specified pre-tension may be applied to the wireline 24. This tension may be a minimum attention that always present in the wireline 24 during deployment and retrieval of the tool string 52.

After one or more desired well operations are completed, a tension is applied to the wireline 42. When the tension exceeds the activation level of the slip joint 56, the slip joint 56 axially lengthens. This lengthening is caused by the upper section 78 moving away from the lower section 80 and the sealing elements 62. As the upper section 78 slides upward, the connected links 82 pull the ring 66 over the outer surfaces of the sealing elements 64, which collapses the sealing elements 64 into a radially compact closed position. At this stage, the tool string 52 and the flow tool 50 may be retrieved from the wellbore. It should be appreciated that the sail 72 of the FIG. 4 embodiment may also be deployed in a similar manner.

Referring now to FIG. 5, there is shown another flow tool 50 according to the present disclosure wherein a flow restrictor is formed as a shell. The flow tool 50 may include expandable members 102, a shell 104 enclosing the expandable members 102, and a slip joint 56. The expandable members 102 may be rods, arms, plates, strips, bands, tubes, or other like structures that are suitable for displacing the shell 104 radially outward. In one arrangement, the expandable members 102 may include one or more circumferentially arrayed link assemblies 106 that extend radially outward when compressed. The link assemblies 106 may include pair hinged links that are connected between the upper section 78 of the slip joint 56 and the lower section 80 of the slip joint 56. The shell 104 may be shaped as a sleeve that is connected at the upper end to the upper section 78 and the lower section 80 using suitable fastening elements such as bands 108. The shell 104 may be formed of a pliant material; e.g., a sheet of a rubber-type material that includes woven fabric layers or other flexible material suitable for downhole use. In some embodiments, the outer surface of the shell 104 may include features such as ribs 110 to enhance a sealing contact with an adjacent wellbore tubular surface. Also, the shell 104 may include rigid or semi-rigid support members such as rods (not shown) that assist the shell 104 to have a pre-defined shape (e.g., annular) when opened.

When the slip joint 56 closes, the links 106 rotate as they are pushed together and move to an extreme outer diametrical position, which expands the shell 104 to a diametrically enlarged position. When the slip joint 56 opens, the links 106 are pulled apart and radially retract toward the slip joint 56. FIG. 6 shows the links 106 in a diametrically retracted condition where the slip joint 56 is open and the expandable members 102 are diametrically retracted.

Referring now to FIG. 7, there is shown yet another embodiment of a flow tool 50 in accordance with the present disclosure wherein the flow restrictor is formed as bellows. The flow tool 50 may include bellows 120, and a slip joint 56. The bellows 120 may include a foldable sleeve 122 made of a suitable flexible material. Fastening elements 124 may be used to attach the distal ends of the bellows 120 to the slip joint upper and lower sections 78, 80, respectively. When the slip joint 56 is an axially shortened condition (closed), the bellows 120 is folded and compressed, which causes the material of the sleeve 122 to radially expand and obstruct the fluid flow path between the pump down tool 50 and an adjacent wellbore tubular wall. When a preset amount of tension is applied, the upper section 78 and the lower section 80 of the slip joint 56 move axially away from one another. This relative motion causes the slip joint 56 to radially lengthen and unfold the bellows 120, which causes a minimal flow obstruction along the flow tool 50 as shown in FIG. 8.

Referring now to FIG. 9, there is shown an embodiment of a slip joint 56 that may be used to actuate the bellows 120. The flow tool 50 may include bellows 120, and a slip joint 56. The bellows 120 is shown in the de-activated position wherein fluid flow through the annulus 55 is only minimally blocked. This de-activated position is associated with the slip joint 56 being in an open position, i.e., axially lengthened. The slip joint 56 includes an upper section 78 that may be formed as a cylinder 130 and a lower section 80 can includes a piston 132 that reciprocates in the cylinder 130. A shaft 134 may connect the piston 132 to the lower end of the tool string 40. In some embodiments, the slip joint 56 may include a biasing element 136 to urge or push the piston 132 toward a desired position (e.g., open or closed). The biasing element 136 may be a coiled spring, leaf spring, spring washers, or other similar structure for applying a biasing force to the piston 132. In FIG. 9, the biasing element 136 is shown pushing the piston 132 uphole, which would tend to close the slip joint 56 and maintain the bellows 120 in the diametrically expanded, flow-blocking condition. Thus, applying a tension force on the conveyance device 42 (FIG. 1) overcomes the spring force of the biasing element 136, which opens the slip joint 56 and closes retracts the bellows 120.

Referring now to FIG. 10, there is shown an embodiment of a slip joint 56 that may be used to actuate a sail, sealing elements, or other umbrella-type of flow restrictors that spread and retract circumferentially. The flow tool 50 may include a variable diameter umbrella-type flow restrictor 150 and a slip joint 56. The flow restrictor 150 is shown in the activated position wherein fluid flow through the annulus 55 is substantially blocked. This activated position is associated with the slip joint 56 being in a closed position, i.e., axially shortened. The slip joint 56 includes an upper section 78 that may be formed as a cylinder 130 and a lower section 80 can includes a piston 132 that reciprocates in the cylinder 130. A shaft 134 may connect the piston 132 to the lower end of the tool string 40. In some embodiments, the slip joint 56 may include a biasing element 136 to urge or push the piston 132 toward a desired position (e.g., open or closed). The biasing element 136 may be a coiled spring, leaf spring, spring washers, or other similar structure for applying a biasing force to the piston 132. An expander 152 may be used to expand and retract the flow restrictor 150. An expander 152 may be connected to the upper section 78 and slide along an inner surface of the flow restrictor 150. The flow restrictor 150 is connected at one end to the lower section 80.

In FIG. 10, the biasing element 136 is shown pushing the piston 132 uphole, which would tend to close the slip joint 56 and maintain the flow restrictor 150 in the diametrically expanded, flow-blocking condition. When the expander 152 slides axially away from the free end of the flow restrictor 150 to the connected end of the flow restrictor 150, the flow restrictor 150 expands diametrically outward. This action is due to the ramp-like interaction between the flow restrictor 150 and the expander 152. The expander 152 may be connected to the flow restrictor 150. For example, the expander 152 may ride along slots or rails formed on the flow restrictor 150. Applying a tension force on the conveyance device 42 (FIG. 1) overcomes the spring force of the biasing element 136, which opens the slip joint 56 and allows the flow restrictor 150 to retract. Biasing elements (not shown) may be used to bias the flow restrictor 150 to the closed position.

To further illustrate the uses of the present disclosure, the present teachings will be described in the context of methods and devices for reducing the amount of fluid used during hydraulic fracturing (or “fracking”) operations. In many instances, fracking is used in unconventional reservoirs such as gas-shale plays. Referring back to FIG. 1, the wellbore trajectories for unconventional reservoir generally follow an “L-shape” as shown by the wellbore 10. However, the distal end of the non-vertical leg 19 of the wellbore 10 is drilled upward with a gradient steep enough that produced water can flow toward the “heel” of the wellbore 10. The “heel” is generally the section of the wellbore 10 that is at the lowest depth, normally the junction of the vertical leg 17 and the non-vertical leg 19. The water collecting at the “heel” may be pumped uphole and out of the wellbore 10. This arrangement effectively avoids the accumulation of water that may otherwise hinder or shut down gas production.

During completion of a well, it may be desired to perform a fracking operation at one or more zones along the non-vertical leg 19 of the wellbore 10. One illustrative fracking operation first uses a “plug and perforate” technique (or “PNP”) before each hydraulic fracking operation. During a typical PNP, the bottomhole assembly (BHA) 40 may include a drillable plug, a setting tool, and an array of perforating guns. The BHA 40 may be conveyed into the tubular 20 via a wireline or other suitable non-rigid carrier. Since gravity cannot move the BHA 40 along the non-vertical leg 19, a fluid such as water is pumped into the tubular 20 to flow the BHA 40 to the desired wellbore location. Once positioned at the furthest zone to be fractured, the plug is set using the setting tool. Then the perforating guns, which are uphole of the plug, are fired to perforate the first interval. Thereafter, the BHA 40 is pulled out of the wellbore 10 and fracking job is performed in the first interval. Once fracturing is completed, a second BHA 40 is conveyed into the tubular 20 and a second plug is set uphole of the first interval. The second BHA perforating gun is fired to perforate the second interval. Again, the BHA 40 is retrieved from the well and the second interval is fractured. The plug uphole of the first interval isolates the first interval from this second fracking operation. This process may be repeated for as many intervals as desired. Once all fracking operations are completed, a coiled tubing conveyed drilling tool may be used to drill out the plugs and open the bore of the tubular 20 for production.

As can be appreciated, the volume of water required by the numerous pump down operations during fracking may impose considerable logistics and operational constraints, such as significant long rig times, all of which translate into costly operations. Moreover, the pump down operation may include variables that prevent an accurate modeling before the actual PNP job. Therefore, personnel may select pump rates and running speeds based on historical data or generalized assumptions. These methodologies may not accurately predict tool movement or velocity. Thus, rig personnel may select operating parameters that result in excessive or uneven tool speed. In some instances, such movement of the tools and conveying cable during the pump down operations can result in damaged cables or connection points and even necessitate fishing jobs to recover lost tools.

Referring now to FIG. 11 there is shown a flow tool 200 that may be used in connection with a fracking operation that can reduce the amount of water used convey related tools into the wellbore. The flow tool 200 may include a conveyance assembly 220, a sensor section 240, a tool section 260, and a flow restrictor 280. The flow tool 200 may be positioned in a desired orientation using one or more stand-off members 202. The stand-off members 202, which may be bow springs, ribs or stands, may center the flow tool 200 in the wellbore tubular 20. The desired orientation may be a centralized position relative to the bore of the wellbore tubular or an eccentric/decentralized orientation.

The conveyance assembly 220 may include a non-rigid conveyance device 222 and a cablehead assembly 224. The conveyance device 222 may be a wireline (power and data) or e-line (power only) depending on the devices on-board the flow tool 200. A wireline may be used when the flow tool 200 includes instruments, processors, actuators, and other devices that are controlled using control signals send by the operators at the surface. If such devices are not present, then an e-line may be used to energize the electrical devices associated with the flow tool 200. Of course, some electrical devices may be controlled simply by manipulating power flow (e.g., cycling power on and off). The cablehead assembly 224 may include a tension release device that may be actuated to disconnect the flow tool 200 from the conveyance device 222.

The sensor section 240 may include one or more sensors for determining a position (e.g., location or orientation) of the tool 200 and/or one or more parameters relating to the wellbore. For example, position parameters may be determined using information obtained from casing collar locators (CCL) and gamma ray (GR) correlation devices. CCL tools may be used to maintain a count of casing joints in order to estimate tool depth whereas GR correlation devices can generate gamma ray logs that can be correlated with previously obtained gamma ray logs to identify a particular formation. Instruments such as gyroscopes, magnetometers, inclinometers, and accelerometers may also be used to obtain an orientation or location of the flow tool 200. These and other similar devices may be used to determine the position of the tool 200 relative to a known feature or actual distance travelled. As described later, such tools may be used to detect or identify events in order to operate the tool 200.

The sensor section 240 may also include sensors for determining the status or condition of one or more on-board devices. The condition or status of tooling may be obtained using displacement sensors that determine the position of various tool components. Wellbore conditions may be determined using temperature gages, pressure gages, etc.

The sensor section 240 may also include sensors for determining one or more parameter relating to the formation. For example, the sensor section 240 may include formation evaluation sensors such as resistivity tools, nuclear magnetic resonance (NMR) tools, gamma ray detectors, acoustic tools, and other well logging tools that provide information relating to a geological parameter, a geophysical parameter, a petrophysical parameter, and/or a lithological parameter. Thus, the sensor section 240 may include sensors for estimating formation resistivity, dielectric constant, the presence or absence of hydrocarbons, acoustic porosity, bed boundary, formation density, nuclear porosity and certain rock characteristics, permeability, capillary pressure, and relative permeability. It should be understood that this list is illustrative and not exhaustive.

The tool section 260 may include one or more tools for performing one or more desired wellbore operations. For PNP-related activities, the tool section 260 may include a plug, a setting tool, and one or more perforating guns.

The variable diameter flow restrictor 280 is a signal-actuated propulsion device that can be used to convey and position the flow tool 200 at a desired location in the wellbore. In one embodiment, the flow restrictor 280 may be an annular-shaped member that can diametrically expand and retract to block flow along an annulus 55 between the wellbore tubular 20 and the flow tool 200. In the diametrically expanded condition, the flow restrictor 280 may be approximately the same diameter as an inner diameter of a wellbore tubular 20 and form a sliding seal with the adjacent tubular wall 21. As discussed in connection with previous embodiments, this form of contact may be referred to a hydraulic sealing engagement or simply ‘sealing engagement,’ but does not require physical contact between adjacent surfaces. This seal allows the relatively higher pressure uphole of the flow tool 200 to propel the tool string 52 through the wellbore tubular. In one embodiment, the flow restrictor 280 may include one or more sealing elements 282 and a signal-responsive actuator 284 for moving the sealing elements 282. The flow restrictor may also include one or more tension springs 286 that are connected to the sealing elements 282 and bias the sealing elements 282 to a radially retracted position. An embodiment with a single sealing element 282 may be formed as a ring-shaped member. An embodiment with multiple sealing elements 282 may be formed as circumferentially-segmented pie-shaped or fan-shaped members. In either instance, the element(s) 282 present a surface that radially traverses the gap between the tool body and the adjacent wellbore wall.

Referring now to FIG. 12, there is shown a sealing element 282 of the flow restrictor 200 (FIG. 11) that is formed as a petal. In one embodiment, the sealing element 282 may be a continuous ring shaped member that surrounds a support 288. Thus, several sealing elements 282 may be circumferentially arrayed around the support 288. The support 288 may be a mandrel, a tube, a rod, or other suitable support member. The sealing elements 282 may be interleaved and fixed at one end to the support 284 with a pin 285. When open, the sealing elements 282 form a basket shape that captures flowing fluids. The arrangement and construction of the sealing elements 282 may be similar to the previously described in connection with FIG. 4.

The actuator 284 may be used to rotate the sealing elements 282 radially outward in order to block the surrounding annular flow passage. The actuator 284 may use a geared electric motor, solenoid, piston-cylinder arrangement, pneumatic motor, hydraulic motor any other mechanisms to translate a rod 290 into and out of a sliding engagement with an associated sealing element 282. In one arrangement, an end 292 of the actuator rod 290 seats within a notch 294 formed along a profile 296 of the sealing element 282. The profile 296 has a ramp portion 298 that increases in thickness in a direction toward the notch 294. Thus, as the rod 290 moves axially along the profile 296 and slides along the ramp portion 298, the sealing element 282 rotates radially outward about the pin 285. This radially outward movement is resisted by the tension force of the spring 286.

The opening and closing action of the flow restrictor 280 will be described in connection with FIGS. 12-14. Referring to FIG. 12, to begin, the sealing elements 282 are in a retracted position and rod 290 is operationally disengaged from the profile 296. That is, the sealing elements 282 merely rest on the rod 290. The tension spring 294 applies a tension force that maintains the sealing element 282 in the retracted position. Referring to FIG. 13, the actuator 284 (FIG. 12) has been activated by a control signal, which causes the rod 290 to travel axially toward the notch 294. The sliding engagement with the ramp portion 298 forces the sealing element 282 to rotate radially outward until the end 292 of the rod 290 seats within the notch 294. Thus, the sealing element 282 is supported in an intermediate open position by the rod 290, which allows the sealing element 282 to obstruct fluid flow along the annulus 55 (FIG. 11). Referring to FIG. 14, when the surface pumps are energized, pressurized fluid flows into the tubular 20. The obstruction caused by the partially open sealing elements 282 enable hydraulic force to push the sealing element 282 into a fully open position to provide a maximum flow obstruction in the annulus 55 (FIG. 11). This hydraulic force propels the flow tool 200 along the wellbore tubular 20 (FIG. 11).

To close the flow restrictor 280, the process is reversed. Terminating pump operation stops fluid flow in the annulus 55 (FIG. 11), which reduces and eventually eliminates the hydraulic forces keeping the sealing elements 282 open. The sealing elements 282 retract to the intermediate open position wherein the sealing elements 282 are supported by the rod 290. The biasing force of the spring element 286 may urge this closing action. Finally, a control signal received by the actuator 284 (FIG. 12) causes the rod 290 to slide out of engagement with the notch 294. As the rod 290 disengages from the sealing element 282, the spring 286 pulls the sealing element 282 into the radially retracted position.

It should be understood that the actuation of the sealing elements 282 shown in FIG. 12 is only illustrative in nature. The actuator 284 may be used to fully rotate the sealing elements 282 radially outward into engagement with an adjacent wellbore wall. That is, an intermediate position may not be used. Thus, the actuator 284 may move the sealing elements 282 to position at least intermediate to the full open position or to the full open position itself. In such an arrangement, the actuator 284 is the primary mechanism to fully open the sealing elements 282. Pumping fluid into the well will provide supplemental opening force. A spring may be used to collapse the sealing elements 282 to a closed position and/or the actuator 284 may be used to retract the sealing elements 282.

Referring now to FIGS. 15A-C, there are shown the several stages to the operation of the flow tool 200. In FIG. 15A, the flow restrictor 280 is shown in a fully retracted position as the tool travels through the tubular 20 using primarily gravity. Once it is desired to activate the flow restrictor 200, a control signal is sent to the actuator 284 (FIG. 11) via the wireline 222 (FIG. 11). In response, the actuator 284 (FIG. 11) axially displaces the rod 290 (FIG. 11) to partially open the sealing elements 282 of the flow restrictor 280, as shown in FIG. 15B. The control signal may be sent from the surface via a wireline 222 or be transmitted from a downhole processor (not shown). Pumps may be activated at the surface to flow water or other fluid into the tubular 20 (FIG. 11). This flowing fluid applies hydraulic pressure that opens the sealing elements 282 to the fully radially extended position shown in FIG. 15C. The sealing elements 282 may form a seal with an interior surface 21 of the tubular 20. The hydraulic pressure thereafter propels the flow tool 200 through the tubular 20. As the flow tool 200 moves through the tubular 20, the pump rate and the wireline speed may be coordinated to keep a tension on the cablehead 224 (FIG. 11) that is within a predetermined range, below a preset value, or above a preset value.

The flow tool 200 travels along the tubular 20 until the target depth is reached. In one embodiment, on-board sensors measure one or more parameters of interest (e.g., gamma rays) that are indicative of the formation at the target depth. The on-board sensors may also detect casing collars or estimate the distance travelled using accelerometers or other device. This information may be transmitted to the surface via the wire and/or processed downhole.

Upon determining that the target depth has been reached, the pumps are secured to stop the downward flow of fluid. The tension provided by the springs 286 rotates the sealing elements 282 to the intermediate closed position as shown in FIG. 15B. Next, a control signal is sent to the actuator 284. In response, the actuator 284 pulls the rod 290 away from the sealing elements 282, which allows the spring 286 to pull the sealing elements 282 to the fully closed position as shown in FIG. 15A. The tool may then be pulled out of the wellbore 10.

From the above, it should be appreciated that the seal formed after the sealing elements 282 are fully opened minimizes the amount of water that can flow past the flow tool 200. Thus, an immediate benefit is that the amount of water required to pump down the tool string in the well is reduced significantly. Further, personnel can estimate the volume of the fluid column that is required to push the flow tool 200 to a particular target depth. Because the amount of needed water is predictable, personnel can better select operating set points (e.g., volumetric flow rate or tool velocity) during the pump down operation to maintain tool stresses within prescribed ranges.

Additionally, the ability to combine the pump down instruments with other logging instruments above and below the flow restrictor 200 enables monitoring the deployment operation while acquiring logging data during the pump down operation. This functionality may save time and enable applications additional operations, e.g., detect fluid communication behind the casing between fracked sections.

In some embodiment, the tool string may use an arrangement other than a non-rigid conveyance device for movement along the wellbore. Referring now to FIG. 16, there is shown a tool string 300 constructed as an autonomous drop tool that is not tethered to a cable or line. The autonomous tool 300 may optionally include a fishing neck or latching mechanism 302 that engages with a retrieval tool (not shown). After the desired wellbore operations are performed, the retrieval tool, which may be a rigid or non-rigid conveyance device, is used to pull the autonomous tool 300 out of the wellbore 10. In another embodiment, the autonomous tool may be destroyed in the wellbore. In still another embodiment, the autonomous tool may be displaced into a ‘rat hole’ of the wellbore 10. As is known, a ‘rat hole’ is a length of the wellbore at the bottom that is specifically designated for receiving debris. In yet embodiments, the autonomous tool may be coupled to a wellbore tractor (not shown). The wellbore tractor may be a self-propelled robotic device that uses wheels or anchoring pads to move along the wellbore 10. The term “carrier” or “conveyance device” as used herein means any device, device component, combination of devices, media and/or member that may be used to convey, house, support, or otherwise facilitate the use of another device, device component, combination of devices, media and/or member.

The autonomous tool configuration may be controlled using a variety of methodologies. In one embodiment, the autonomous tool may be responsive to control signals. An illustrative signal-responsive autonomous tool may include a communication interface 304 that can receive control signals. The control signals may be pressure pulses, acoustical signals, electrical signals, or any other type of information-encoded signal. These signals may be conveyed via a fluid in the borehole or by a wellbore tubular. The autonomous tool may include an information processing device 306 programmed to take one or more specified actions upon receiving a control signal. The control signal may be transmitted from a remote location, such as at the surface or another location in the wellbore. The information processing device may include one or more processor(s) that can be a microprocessor that uses a computer program implemented on a suitable machine readable medium that enables the processor to perform the control and processing. The machine readable medium may include ROMs, EPROMs, EAROMs, EEPROMs, Flash Memories, RAMs, Hard Drives and/or Optical disks. Other equipment such as power and data buses, power supplies, and the like will be apparent to one skilled in the art.

In another embodiment, the autonomous tool 300 may be programmed to take actions based on a preprogrammed protocol and using locally generated, as opposed to remotely generated, control signals. In such an embodiment, the information processing device 306 may be programmed to take one or more specified actions upon the occurrence of a pre-determined event. The event may be a condition, status, or state. Illustrative, but not exhaustive, events include a duration of time (e.g., 30 minutes), a measured environmental parameter (e.g., pressure, temperature, flow rate, etc.), a travelled distance (e.g., estimated by motion sensors or counting casing collars), a specific wellbore orientation (e.g., inclination, azimuth), and a formation parameter (e.g., gamma ray count). An event detector 308 configured to estimate the occurrence of one or more of these events may generate a local control signal to the information processing device 306 when the event is detected. For example, the event detector 308 may generate a control signal to open the sealing members when a first depth is reached and to close the sealing member when a second depth is reached. Whether or the first or the second depth has been reached can be based on estimate of time lapse, motion, pressure, flow rate, gamma logs, casing collar count, etc.

Referring still to FIG. 16, the autonomous tool 300 is shown decentralized in the wellbore 10. That is, the long axis of the tool 300 is radially offset from the long axis of the wellbore 10. The sealing member or members 310 accommodate this eccentricity by extending radially in different amount, depending on the circumferential position. In some embodiments, the sealing members 310 may be resilient or deformable in order to conform to the eccentric tool position. In other embodiments, the sealing members 310 may be configured to be independently actuated to different radial lengths to accommodate the eccentric positioning of the tool 300. Thus, the sealing members 310 may passively or actively assume an asymmetric radial positioning. It should be appreciated that such sealing members 310 can adapt to changes in the diameter or shape of the bore of the wellbore tubular being traversed while maintain a sealing engagement with the wellbore tubular.

While the present disclosure discusses a hydrocarbon producing well, the present teachings may also be used with other types of wells (e.g., geothermal wells, water wells, etc.) While the foregoing disclosure is directed to the one mode embodiments of the disclosure, various modifications will be apparent to those skilled in the art. It is intended that all variations within the scope of the appended claims be embraced by the foregoing disclosure. 

We claim:
 1. An apparatus for flowing a tool string along a wellbore tubular, comprising: a flow restrictor having a diametrically expanded position and a diametrically retracted position, wherein the flow restrictor includes: at least one sealing element that sealingly engages the wellbore tubular when in the diametrically expanded position; and an actuator configured to move the at least one sealing element to at least a position intermediate of the open and the closed position, the actuator being responsive to a control signal.
 2. The apparatus of claim 1, wherein the at least one sealing element expands from the intermediate position to the diametrically expanded position in response to an applied hydraulic force.
 3. The apparatus of claim 1, further comprising a non-rigid conveyance member connected to the actuator, wherein the non-rigid conveyance is configured to convey the control signal to the actuator.
 4. The apparatus of claim 1, wherein the at least one sealing element is rotatably connected to a support, and further comprising a spring member connected to the at least one sealing element and urging the at least one sealing element to the diametrically retracted position.
 5. The apparatus of claim 1, wherein the actuator includes a rod and the at least one sealing element includes a profile having a ramp portion and a notch, wherein sliding engagement between the rod and the ramp portion moves the ate least one sealing element to the intermediate position, and wherein engagement between the rod and the notch supports the at least one sealing element in the intermediate position.
 6. The apparatus of claim 1, wherein the at least one sealing element includes a plurality of sealing elements circumferentially arrayed around a support, the plurality of sealing elements configured to form a substantially annular seal with the wellbore tubular when in the diametrically expanded position.
 7. The apparatus of claim 1, further comprising a tool section connected to the flow restrictor, the tool section configured to perform at least one selected wellbore operation.
 8. The apparatus of claim 7, further comprising a sensor section connected to the flow restrictor, the sensor section configured to estimate at least one parameter associated with at least one of: (i) the flow restrictor, (ii) the tool section, (iii) the wellbore tubular, (iv) a position of the flow restrictor, (v) a wellbore, and (vi) a formation.
 9. The apparatus of claim 7, wherein the tool section includes at least a bore isolation device, a setting tool for actuating the bore isolation device, and at least one perforating gun.
 10. The apparatus of claim 9, wherein the further comprising a sensor section connected to the flow restrictor, the sensor section configured to estimate at least one parameter associated with a perforation formed by firing the at least one perforating gun.
 11. The apparatus of claim 1, wherein the actuator is responsive to a signal transmitted from one of: (i) a surface location, and (ii) an event detector configured to detect a pre-determined event in the wellbore.
 12. A method for flowing a tool string along a wellbore tubular, comprising: disposing a flow tool having a flow restrictor into the wellbore tubular, wherein the flow restrictor has a diametrically expanded position and a diametrically retracted position; using a control signal to move the flow restrictor to at least a position intermediate between the diametrically expanded position and the diametrically retracted position; pumping fluid into the wellbore tubular; propelling the flow restrictor and the tool string through the wellbore by sealingly engaging a surface of the wellbore tubular with the flow restrictor in the diametrically expanded position; terminating the pumping once a target depth has been reached by the tool string; and using a control signal to move the flow restrictor to the diametrically retracted position.
 13. The method of claim 12, further comprising expanding the flow restrictor to engage an inner surface of the wellbore tubular using a pressure applied by the fluid flowing in the wellbore tubular.
 14. The method of claim 12 further comprising connecting a non-rigid conveyance device to the flow tool, and using the non-rigid conveyance device to transmit the control signal to the actuator.
 15. The method of claim 12, further comprising estimating a volume of fluid to be used during the pumping, and controlling a tension on a non-rigid conveyance device connected to the flow restrictor based at least on the estimated volume of fluid.
 16. The method of claim 12, further comprising: perforating a selected interval in the wellbore before retrieving the tool.
 17. The method of claim 16, further comprising: logging the perforated selected interval before retrieving the tool.
 18. The method of claim 12, wherein the control signal is transmitted from a surface location.
 19. The method of claim 12, further comprising retrieving the flow restrictor and the tool string from the wellbore tubular. 